Simultaneous crude oil dehydration, desalting, sweetening, and stabilization with compression

ABSTRACT

Integrated gas oil separation plant systems and methods, one system including a crude oil inlet feed stream; a low pressure production trap (LPPT); a low pressure degassing tank (LPDT); a first heat exchanger, where the first heat exchanger is fluidly disposed between the LPPT and LPDT, and is fluidly coupled to both the LPPT and LPDT, and where the first heat exchanger is operable to heat the LPDT inlet feed stream with compressed gas removed from the crude oil inlet feed stream; a first inline gas mixer preceding the LPPT to directly mix compressed gas from the LPDT into the LPPT inlet feed stream; and a LPDT recycle water stream, where the LPDT recycle water stream is operable to supply recycle water from the LPDT to the LPPT inlet feed stream.

BACKGROUND Field

The present disclosure relates to gas oil separation plant (GOSP)technology. In particular, the disclosure relates to integrating crudeoil desalting, dehydration, sweetening, and stabilization processes tocreate efficient GOSP systems and processes with compression of gasesused for heating to aid in separations.

Description of Related Art

In general, a GOSP is a continuous separation process used to refinecrude oil that includes a high pressure production trap (HPPT), a lowpressure production trap (LPPT), a low pressure degassing tank (LPDT), adehydrator unit, first and second stage desalting units, a water/oilseparation plant (WOSEP), a stabilizer column, centrifugal pumps, heatexchangers, and reboilers. In a GOSP, the pressure is often reduced inseveral stages to allow the controlled separation of volatilecomponents, such as entrained vapors. Goals of a GOSP include achievingmaximum liquid recovery with stabilized oil separated from gas, andwater separated from gases and oil. In other words, one purpose of aGOSP is to remove water, salt, and volatile hydrocarbon gases from wetcrude oil after it is obtained from a hydrocarbon-bearing reservoir.

However, a large pressure reduction in a single separator will causeflash vaporization, leading to instability and safety hazards. Thus, inprior art GOSP's, many stages and units are required, as described inU.S. Pat. Nos. 10,260,010 and 10,023,811, incorporated herein byreference in their entirety. In a first stage, gas, crude oil, and freewater are separated. In a second stage, crude oil is dehydrated anddesalted to separate emulsified water and salt to meet certain basicsediment and water (BSW) specifications. In a third stage, crude oil isstabilized and sweetened to meet hydrogen sulfide (H₂S) and Reid VaporPressure (RVP) specifications.

GOSP's are oftentimes operated to meet the following specifications: (1)a salt concentration of not more than about 10 pound (lbs.) of salt/1000barrels (PTB); (2) BSW content of not more than about 0.3 volume percent(V %); (3) H₂S content (concentration) of less than about 60 ppm ineither the crude stabilization tower (or degassing vessels in the caseof sweet crude); and (4) a maximum RVP of about 7 pounds per square inchabsolute (psia) and a maximum true vapor pressure (TVP) of about 13.5psia at 130 degrees Fahrenheit (° F.).

SUMMARY

The present disclosure describes integrated GOSP systems and processesthat meet crude oil export specifications and use less processing unitsthan prior art GOSP's. By integrating and simultaneously applyingdesalting, dehydration, sweetening, and stabilization processes alongwith gas compression and gas recycle for heating within certainpre-existing gas/oil separation vessels, advantageously and unexpectedlyefficient processes and systems are obtained. Systems and methods of thepresent disclosure can achieve crude oil export specificationsincluding: (1) a salt concentration of not more than about 10 PTB; (2)BSW content of not more than about 0.3 V %; (3) H₂S content of less thanabout 60 ppm in either the crude stabilization tower (or degassingvessels in the case of sweet crude not requiring a stabilization tower);and (4) a maximum RVP of about 7 psia and a maximum TVP of about 13.5psia at 130° F.

Embodiments of systems and methods of the disclosure provide the abilityto separate and stabilize crude oils with “tight” emulsions andincreased water cuts that existing GOSP systems and methods cannotseparate and stabilize. In other words, conventional desalters can treatcrude oils with a water cut between about 30% and about 35% by volume.However, embodiments of the present disclosure efficiently treat crudeoils to remove water when the water cut is greater than about 35%. Tightemulsion crude oil normally occurs in medium to heavy crude oils withAmerican Petroleum Institute (“API”) numbers less than about 29. Oilspecific gravity in the API scale is typically used as a measure of oilquality. A higher API value indicates a lighter oil and, thus, a highermarket value.

Water cut in oil production refers to the total volume of water in thecrude oil stream divided by the total volume of crude oil and water. Inother words, water cut percent is equal to the total volumetric flowrateof water divided by the volumetric flowrate of water and oil multipliedby 100. Water cut generally increases with the age of an oil well. Forexample, water cut at the beginning of the life of a well is around zeropercent, but as the well ages, water cut can reach close to 100%.

In certain embodiments, systems and methods are provided to treat wetand sour, unstabilized crude oil to meet shipping and transportspecifications by simultaneously dehydrating, desalting, stabilizing,and sweetening the crude oil. In some embodiments, three conventionalstages of processing crude oil will be done in only one stage, system,or process. In some embodiments, crude oil desalting, dehydration,sweetening, and stabilization will be integrated within existing threephase separation vessels within a GOSP along with gas compression andgas recycle for heating. Dehydrating crude oil involves the separationof formation water, while desalting includes washing the crude withfresh water in addition to or alternative to recycle water to meet therequired salt content and BSW. Recycled water can be used in disclosedsystems and methods to reduce the amount of fresh wash water required.

Crude sweetening involves the removal of dissolved H₂S from crude oil tomeet specifications in a range of about 10-60 ppmw, while crudestabilization involves the removal of light ends from crude oil, mainlyC₁-C₄ hydrocarbons to reduce the TVP to less than about 13 psia at 130°F. below atmospheric pressure, or in other words no vapor will flashunder atmospheric conditions, making it safe for transportation andshipment. Stabilizing the crude can be achieved if crude is heated inmultiple stages of separation drums working at increasing temperaturesand reduced pressure.

Embodiments disclosed here show crude oil components are separated in aseries of separation vessels in which off-gases are removed from theseparation vessels and compressed to heat incoming crude oil to enhancethe separation, in particular focusing on systems and processes with3-phase separation vessels including fully insulated electrostaticelectrodes. In some embodiments the advantages of the systems andprocesses include eliminating certain existing crude oil stabilizercolumns, eliminating crude oil stabilizer reboilers, eliminating crudeoil charge pumps, eliminating 1^(st) and/or 2^(nd) stage desalters, andeliminating separate crude oil dehydrators. Systems and processes arecompact and easily mobilized for deployment in small scale and offshorerig applications. Energy savings and efficiency are increased byseparating water before heating in a HPPT.

Therefore, disclosed herein are integrated gas oil separation plantsystems, one system including a crude oil inlet feed stream; a lowpressure production trap (LPPT), where the LPPT is fluidly coupled tothe crude oil inlet feed stream, and where the LPPT comprises an inletmixing device operable to thoroughly mix an LPPT inlet feed stream, aplurality of insulated electrostatic electrodes, and a weir; a lowpressure degassing tank (LPDT), where the LPDT is fluidly coupled to theLPPT, and where the LPDT comprises an inlet mixing device operable tothoroughly mix an LPDT inlet feed stream, a plurality of insulatedelectrostatic electrodes, and a weir; a first heat exchanger, where thefirst heat exchanger is fluidly disposed between the LPPT and LPDT, andis fluidly coupled to both the LPPT and LPDT, and where the first heatexchanger is operable to heat the LPDT inlet feed stream with compressedgas, the gas removed from the crude oil inlet feed stream; a firstinline gas mixer preceding the LPPT to directly mix compressed gasremoved from the LPDT into the LPPT inlet feed stream; and a LPDTrecycle water stream, where the LPDT recycle water stream is operable tosupply recycle water from the LPDT to the LPPT inlet feed stream.

Embodiments can include an inline gas separator preceding the LPPT toseparate gas from the crude oil inlet feed stream for compression,wherein compressed gas from the inline gas separator and compressedoff-gas from the LPPT is used to provide heat in the first heatexchanger. Other embodiments include a second heat exchanger, where thesecond heat exchanger is fluidly disposed between the LPPT and LPDT, andis fluidly coupled to both the LPPT and LPDT, and where the second heatexchanger is operable to heat the LPDT inlet feed stream with compressedgas, the gas removed from the crude oil inlet feed stream. Certain otherembodiments include a first knock out drum in fluid communication withthe first heat exchanger and a second knockout drum in fluidcommunication with the second heat exchanger, wherein after compressedgas passes through the second knockout drum the compressed gas comprisesnatural gas for further processing to a sales gas.

Still other embodiments include a desalter and a cold stabilizer,wherein atmospheric off-gas from the cold stabilizer is compressed andsent to the first inline gas mixer preceding the LPPT and wherein drycrude oil from the cold stabilizer is used to heat the crude oil inletfeed stream. In some embodiments, the cold stabilizer has about 16actual stages. Still in other embodiments, the system comprises anatmospheric pressure gas compressor and a low pressure gas compressor.In some embodiments, the system comprises an atmospheric pressure gascompressor, a low pressure gas compressor, and a high pressure gascompressor, and the atmospheric pressure gas compressor compressesatmospheric off-gases from the LPDT and the cold stabilizer for supplyto the first inline gas mixer, the low pressure gas compressorcompresses low pressure off-gases from an inline gas separator and theLPPT for supply to the first heat exchanger, and the high pressure gascompressor compresses high pressure off-gases from the first heatexchanger for supplying heat to the second heat exchanger. Still otherembodiments include a fresh wash water supply stream, where the freshwash water supply stream is operable to supply fresh water to an outputstream of the LPDT.

Other embodiments include a stripping gas stream inlet fluidly coupledwith the LPDT, the stripping gas stream inlet operable to supply steam,in addition to or alternative to a low concentration H₂S stripping gas,to the LPDT. Some embodiments include an oil/water separator deviceoperable to accept an oily water output stream from the LPPT, andoperable to separate oil from water. In some embodiments, the system isoperable to refine crude oil in the crude oil inlet feed stream toproduce a refined crude oil product safe for storage and shipmentmeeting the following specifications: (1) a salt concentration of notmore than about 10 pound (lbs.) of salt/1000 barrels (PTB); (2) basicsediment and water (BSW) of not more than about 0.3 volume percent (V%); (3) H₂S concentration of less than about 60 ppm; and (4) a maximumRVP of about 7 pounds per square inch absolute (psia) and a maximum truevapor pressure (TVP) of about 13.5 psia at 130 degrees Fahrenheit (°F.).

Other embodiments include a high pressure production trap (HPPT), wherethe HPPT is fluidly coupled to the crude oil inlet feed stream andprecedes the LPPT, and where the HPPT comprises an inlet mixing deviceoperable to thoroughly mix the crude oil inlet feed stream with anadditional fluid, a plurality of insulated electrostatic electrodes, anda weir. Still other embodiments include a high pressure inline gasseparator preceding the HPPT to separate gas from the crude oil inletfeed stream for compression and a second inline gas mixer preceding theHPPT to directly mix compressed off-gas from the LPPT into an HPPT inletfeed stream. Still other embodiments include a LPPT recycle waterstream, where the LPPT recycle water stream is operable to supplyrecycle water from the LPPT to be mixed with the HPPT inlet feed stream.In yet other embodiments, the system comprises an atmospheric pressuregas compressor, a low pressure gas compressor, and a high pressure gascompressor, and the atmospheric pressure gas compressor compressesatmospheric off-gases from the LPDT and from an atmospheric pressureinline gas separator preceding the LPDT to be sent to the first inlinegas mixer, the low pressure gas compressor compresses low pressureoff-gases from the LPPT to be sent to the second inline gas mixer, andthe high pressure gas compressor compresses high pressure off-gases fromthe crude oil inlet feed stream and the HPPT to be sent to the firstheat exchanger. Still other embodiments include a fresh wash watersupply stream, where the fresh wash water supply stream is operable tosupply fresh water to an output stream of the LPPT.

Some embodiments include a stripping gas stream inlet fluidly coupledwith the LPDT, the stripping gas stream inlet operable to supply steam,in addition to or alternative to a low concentration H₂S stripping gas,to the LPDT. Other embodiments include an oil/water separator deviceoperable to accept an oily water output stream from the HPPT, andoperable to separate oil from water. In some embodiments, the system isoperable to refine crude oil in the crude oil inlet feed stream toproduce a refined crude oil product safe for storage and shipmentmeeting the following specifications: (1) a salt concentration of notmore than about 10 pound (lbs.) of salt/1000 barrels (PTB); (2) basicsediment and water (BSW) of not more than about 0.3 volume percent (V%); (3) H₂S concentration of less than about 60 ppm; and (4) a maximumRVP of about 7 pounds per square inch absolute (psia) and a maximum truevapor pressure (TVP) of about 13.5 psia at 130 degrees Fahrenheit (°F.). Some embodiments include a high pressure knockout drum to accepthigh pressure gas from the first heat exchanger and operable to producea suitable natural gas for further processing to a sales gas.

Still other embodiments include at least one mixing valve preceding theHPPT, at least one mixing valve preceding the LPPT, and at least onemixing valve preceding the first heat exchanger, where the mixing valvesare operable to mix crude oil and water. In some embodiments, the HPPTis operable to remove about 98% of emulsified water present in crude oilfrom the crude oil inlet feed stream. Still in other embodiments,operating pressure within the HPPT is greater than the operatingpressure within the LPPT, and the operating pressure within the LPPT isgreater than the operating pressure in the LPDT. In certain otherembodiments, the system is operable to dehydrate, desalt, sweeten, andstabilize crude oil to produce crude oil safe for storage and shipmentwithout any dehydrating or desalting units other than the HPPT, LPPT,and LPDT. Some embodiments include at least one inlet mixing devicecomprising a cyclonic separator.

Additionally disclosed here are methods for integrated gas oilseparation, one method including: supplying a crude oil inlet feedstream; removing from the crude oil inlet feed stream a low pressurecrude oil off-gas stream for compression; heating the crude oil inletfeed stream with heat provided by processed dry crude oil; mixing thecrude oil inlet feed stream with compressed low pressure gas from a lowpressure degassing tank (LPDT) and a cold stabilizer; initiallyseparating the crude oil inlet feed stream in a low pressure productiontrap (LPPT) into a LPPT off-gas stream, the LPPT off-gas stream to becompressed with the low pressure crude oil off-gas stream, apartially-dried crude oil stream, and an oily-water stream fortreatment; heating the partially-dried crude oil stream with compressedgas from the low pressure crude oil off-gas stream and the LPPT off-gasstream; further separating the partially-dried crude oil stream in theLPDT to produce a LPDT off-gas stream, a dried crude oil stream, and arecycle water stream for recycle to the crude oil inlet feed stream;desalting the dried crude oil stream to produce a dried, desalted crudeoil stream and a recycle water stream for recycle to the LPDT;stabilizing the dried, desalted crude oil stream to produce a crude oilexport stream, the crude oil export stream used to heat the crude oilinlet feed stream, and an atmospheric off-gas stream; and compressingthe LPDT off-gas stream and the atmospheric off-gas stream for the stepof mixing the crude oil inlet feed stream with compressed low pressuregas from the low pressure degassing tank (LPDT) and the cold stabilizer.

In some embodiments of the methods, the LPPT comprises an inlet mixingdevice operable to thoroughly mix an LPPT inlet feed stream, a pluralityof insulated electrostatic electrodes, and a weir; and the LPDTcomprises an inlet mixing device operable to thoroughly mix an LPDTinlet feed stream, a plurality of insulated electrostatic electrodes,and a weir. In some embodiments, the step of removing from the crude oilinlet feed stream a low pressure crude oil off-gas stream forcompression includes the use of an inline gas separator preceding theLPPT. Some embodiments of the methods include the step of removingcondensate from compressed off-gas using at least one knock-out drum.Still other embodiments include the step of supplying a fresh water washstream to aid in the step of desalting.

Other embodiments include the step of supplying a stripping gas stream,the stripping gas stream to supply steam, in addition to or alternativeto a low concentration H₂S stripping gas. In some embodiments, themethod is operable to refine crude oil in the crude oil inlet feedstream to produce a refined crude oil product safe for storage andshipment meeting the following specifications: (1) a salt concentrationof not more than about 10 pound (lbs.) of salt/1000 barrels (PTB); (2)basic sediment and water (BSW) of not more than about 0.3 volume percent(V %); (3) H₂S concentration of less than about 60 ppm; and (4) amaximum RVP of about 7 pounds per square inch absolute (psia) and amaximum true vapor pressure (TVP) of about 13.5 psia at 130 degreesFahrenheit (° F.).

Additionally disclosed is a method for integrated gas oil separation,the method comprising the steps of: supplying a crude oil inlet feedstream; removing from the crude oil inlet feed stream a high pressurecrude oil off-gas stream for compression; mixing the crude oil inletfeed stream with recycle water from a low pressure production trap(LPPT); mixing the crude oil inlet feed stream with compressed highpressure gas from the LPPT; initially separating the crude oil inletfeed stream in a high pressure production trap (HPPT) into a HPPToff-gas stream, the HPPT off-gas stream to be compressed with the highpressure crude oil off-gas stream, a HPPT partially-dried crude oilstream, and an oily-water stream for treatment; mixing the HPPTpartially-dried crude oil stream with recycle water from a low pressureproduction trap (LPDT) and with compressed atmospheric gas from theLPDT; separating the HPPT partially-dried crude oil stream in the LPPTinto a LPPT off-gas stream, the LPPT off-gas stream to be compressed formixing with the crude oil inlet feed stream, an LPPT partially-driedcrude oil stream, and an oily-water recycle stream; heating the LPPTpartially-dried crude oil stream with compressed gas from the highpressure crude oil off-gas stream and the HPPT off-gas stream; removingfrom the LPPT partially-dried crude oil stream an atmospheric pressureoff-gas stream; and further separating the LPPT partially-dried crudeoil stream in the LPDT to produce a LPDT off-gas stream, the LPDToff-gas stream to be compressed with the atmospheric pressure off-gasstream, a dried crude oil stream, and a recycle water stream for recycleto the LPPT.

In some embodiments, the HPPT comprises an inlet mixing device operableto thoroughly mix an HPPT inlet feed stream, a plurality of insulatedelectrostatic electrodes, and a weir; the LPPT comprises an inlet mixingdevice operable to thoroughly mix an LPPT inlet feed stream, a pluralityof insulated electrostatic electrodes, and a weir; and the LPDTcomprises an inlet mixing device operable to thoroughly mix an LPDTinlet feed stream, a plurality of insulated electrostatic electrodes,and a weir. Still in other embodiments, the step of removing from thecrude oil inlet feed stream a high pressure crude oil off-gas stream forcompression includes the use of an inline gas separator preceding theHPPT. Some embodiments include the step of removing condensate fromcompressed off-gas using at least one knock-out drum. Still otherembodiments include the step of supplying a fresh water wash stream toaid in desalting of crude oil. Other embodiments include the step ofsupplying a stripping gas stream, the stripping gas stream to supplysteam, in addition to or alternative to a low concentration H₂Sstripping gas.

Still in other embodiments, the method is operable to refine crude oilin the crude oil inlet feed stream to produce a refined crude oilproduct safe for storage and shipment meeting the followingspecifications: (1) a salt concentration of not more than about 10 pound(lbs.) of salt/1000 barrels (PTB); (2) basic sediment and water (BSW) ofnot more than about 0.3 volume percent (V %); (3) H₂S concentration ofless than about 60 ppm; and (4) a maximum RVP of about 7 pounds persquare inch absolute (psia) and a maximum true vapor pressure (TVP) ofabout 13.5 psia at 130 degrees Fahrenheit (° F.).

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features, aspects, and advantages of the disclosure willbecome better understood with regard to the following descriptions,claims, and accompanying drawings. It is to be noted, however, that thedrawings illustrate only several embodiments of the disclosure and aretherefore not to be considered limiting of the disclosure's scope as itcan admit to other equally effective embodiments.

FIG. 1 is a schematic diagram showing an integrated GOSP of the presentdisclosure used for processing sour crude oil with integrated gascompression and gas recycle.

FIG. 2 is a schematic diagram showing an integrated GOSP of the presentdisclosure used for processing sweet or slightly sour crude oil withintegrated gas compression and gas recycle.

DETAILED DESCRIPTION

While the disclosure will be described in connection with severalembodiments, it will be understood that it is not intended to limit thedisclosure to those embodiments. On the contrary, it is intended tocover all the alternatives, modifications, and equivalents as may beincluded within the spirit and scope of the disclosure defined by theappended claims.

Conventional GOSP's suffer from many deficiencies including low productyield, inefficient use of available heat sources such as for example thedischarge streams of compressors, many separate units being used to meetproduct specifications, high operating costs due to heatingrequirements, a large spatial footprint, and high capital cost.

In general, a GOSP is a continuous separation system and process thatincludes a high pressure production trap (HPPT), a low pressureproduction trap (LPPT), a low pressure degassing tank (LPDT), adehydrator unit, first and second stage desalting units, a water/oilseparation plant (WOSEP), a stabilizer column, atmospheric compressors,low pressure compressors, high pressure compressors, centrifugal pumps,heat exchangers, and reboilers. In a conventional GOSP, pressure isoften reduced in several stages to allow for the controlled separationof volatile components. Objectives of a GOSP include achieving maximumliquid recovery of stabilized oil and water, and gas separation.However, a large pressure reduction in a single separator will causeflash vaporization, leading to instability and safety hazards.

Prior art GOSP systems and processes generally include 3 separate stagesin large-footprint plants and processes. In a first stage, gas, crudeoil, and free water are separated. In a second stage, crude oil isdehydrated and desalted to separate emulsified water and salt to meetcertain basic sediment and water (BSW) specifications. In a third stage,crude oil is stabilized and sweetened to meet hydrogen sulfide (H₂S) andReid Vapor Pressure (RVP) specifications. Generally, sour crude oilrefers to any crude oil with a total sulfur level of more than about0.5% by weight. In upstream operations, as described herein, the phrasesour crude also refers to any crude oil with an H₂S content higher thanabout 60 ppm by weight, and sweet crude oil refers to any crude oil thathas an H₂S content of less than about 60 ppm by weight.

After stabilization and sweetening, the crude oil should meet allspecifications required for shipment, transport, and storage. Thesespecifications include the following: (1) a salt concentration of notmore than about 10 PTB; (2) BSW of not more than about 0.3 V %; (3) H₂Scontent of less than about 60 ppm in the crude stabilization tower (ordegassing vessels in the case of sweet crude); and (4) a maximum RVP ofabout 7 psia and a maximum TVP of about 13.5 psia at 130° F.

In embodiments of the present disclosure, high pressure off-gases andhigh pressure compressed gases are in a pressure range from about 150psig or about 170 psig to about 460 psig, low pressure off-gases and lowpressure compressed gases are in a pressure range from about 50 psig orabout 70 psig to about 160 psig, and atmospheric pressure off-gases andatmospheric pressure compressed gases are in a range from about 3 psigto about 60 psig. The temperature of the off-gases depends, in part, onthe source of the crude oil. For example, the initial temperature forcrude oil originating from offshore oil rigs ranges between about 55° F.to about 100° F., while the temperature of crude oil originating fromonshore oil fields ranges from about 100° F. to about 150° F. Forexample, in one embodiment the temperature of high pressure off-gas froman HPPT is about 95° F., the temperature of low pressure off-gas from aLPPT is about 95° F. (with no heater preceding the LPPT), and thetemperature of the atmospheric pressure off-gas from a LPDT is about125° F., due to a heater (heat exchanger) preceding the LPDT.

In some embodiments of the present disclosure, the operatingtemperatures of a HPPT and LPPT are substantially the same when noheater (heat exchanger) precedes the units. In some embodiments, theoperating pressure of the HPPT is about 150 psig, the operating pressureof the LPPT is about 50 psig, and the operating pressure of the LPDT isabout 3 psig. In some embodiments, the operating temperatures of theHPPT and LPPT are about 95° F., while the operating temperature of theLPDT is about 125° F.

Referring first to FIG. 1, a schematic diagram is provided showing anintegrated GOSP of the present disclosure used for processing sour crudeoil with integrated gas compression and gas recycle. The directinjection of heated low pressure compressed gas following compression inan atmospheric pressure gas compressor into incoming crude oil to a LPPTwill simultaneously heat the crude and cool the gas. This heated gasfunctions, in part, as a stripping gas in the LPPT and enables meetingan H₂S crude specifications of 10 ppm using a crude oil stabilizer with16 actual trays along with steam injection. Gas from low pressure andhigh pressure compressors is used in the low pressure and high pressuregas-crude heat exchangers, respectively, to heat crude oil, recoverenergy, and cool the gas. The representative embodiments of FIGS. 1 and2 improve crude oil yield at the expense of condensate. In other words,heavy hydrocarbons, such as C₅₊, tend to remain within the crude oil andincrease the crude production while reducing condensate production. Forexample, in some embodiments dry, stabilized crude oil yield is improvedby between about 1 thousand barrels per day (MBD) and about 5 MBD, andcondensate production is decreased between about 1 MBD and about 5 MBDversus prior art systems and methods. Total heating demand can bereduced by between about 30% and about 50%. Total compression powerconsumption can be reduced between about 5% and about 15%.

In integrated compression GOSP system and process 100, a wet andunstabilized crude oil from oil production wells, either or both onshoreor offshore, enters through inlet stream 102 and is mixed with anoptional demulsifier from demulsifier inlet stream 104 to enter inlinegas separator 106 which removes certain volatile off-gases from thecrude oil via off-gas stream 105. Suitable inline gas separators includethose provided by Caltec, United Kingdom, FMC Technologies, Houston, orASCOM Separation. Hydrocarbon off-gases in off-gas stream 105 proceed toa low pressure gas compressor 134 for compression and heating. Mixedcrude oil and optional demulsifier proceed to a mixing valve 110, whichcan include one or more valve or other mixing device, by stream 108, andat mixing valve 110 a recycled water stream 112 from low pressuredegassing tank (LPDT) 176 is mixed into the crude oil and optionaldemulsifier. After mixing valve 110 the mixed stream proceeds via stream114 to heat exchanger 116 for heating of the crude oil, recycle water,and optional demulsifier.

In embodiments disclosed here, when fresh wash water is applied inaddition to or alternative to recycle wash water, a suitablevolume/volume ratio for water to crude oil and hydrocarbons is betweenabout 1 V % to about 9 V %. A lesser V/V wash water to oil andhydrocarbons is used when the salt content is less than 1,000 ppm. Withgreater salt content in wash water, a greater volume is used. Forexample, V/V for recycle water as wash water to crude oil andhydrocarbons is between about 4 V % or 5 V % to about 9 V %.

Heat exchanger 116 can include any one of or any combination of indirectheat exchangers such as shell and tube heat exchangers. The mixed streamof crude oil, recycle water, and optional demulsifier is heated by heatfrom dry crude oil in stream 115 from cold stabilizer 197, and cooled,dry, desalted and stabilized crude oil for shipment proceeds via stream117. Dry crude oil for shipment in line 117 in some embodiments meetsspecifications including the following: (1) a salt concentration of notmore than about 10 PTB; (2) BSW of not more than about 0.3 V %; (3) H₂Scontent of less than about 60 ppm in the crude stabilization tower (ordegassing vessels in the case of sweet crude); and (4) a maximum RVP ofabout 7 psia and a maximum TVP of about 13.5 psia at 130° F.

Heated crude oil, recycle water, and optional demulsifier next proceedvia stream 118 to a direct gas mixer 120 for direct mixing of lowpressure compressed and heated off-gas from stream 119 and atmosphericgas compressor 121. The low pressure compressed and heated off-gas fromstream 119 and atmospheric gas compressor 121 provide further heating tothe mixed stream comprising crude oil, recycle water, and optionaldemulsifier and the gas also acts as a stripping gas for H₂S. The mixedstream of off-gas, crude oil, recycle water, and optional demulsifierproceeds to a low pressure production trap (LPPT) 124, which includes aweir 126, fully-insulated electrostatic electrodes 128, and cyclonicseparator 130. LPPT 124 is a horizontal three-phase separation vessel,which separates certain off-gases from the wet crude oil. Outlets fromLPPT 124 include LPPT low pressure off-gas stream 132, which proceeds tolow pressure gas compressor 134 for compression and heating, oily-wateroutlet stream 136 which proceeds via stream 136 for water treatment inoily-water treatment unit 137, and LPPT wet crude oil outlet stream 138,which proceeds to downstream processing. Operating conditions in LPPT124 include temperature in a range from about 65° F. to about 130° F.and a pressure at about 50 psig, or between about 20 psig and 60 psig.Suitable direct gas mixers include inline nozzles such as thosemanufactured by ProSep of Houston, Tex.

Prior art GOSP systems also suffer from the following issues:transformer tripping and inefficient energy usage; off-specificationcrude oil production in terms of BSW and salt content; high operatingcosts required to meet the crude specifications; and inefficient humanand manual operations. Certain prior art treatments are limited totreating crude oil with a low water cut (approximately 30% by volume),while water cut in certain emulsion layers can reach as high as about85% for tight emulsions in heavy crude oil applications. Suitableinsulated electrostatic electrodes are capable of handling up to 100%water cut herein without short circuiting, and this enhances theemulsion breaking capabilities of separation vessels. Limiting andtreating the emulsion rag layer will avoid off-specification crude oilproducts and minimize demulsifier and wash water consumption. Inembodiments of the disclosure, systems and methods enable the efficientcontrol, reduction, in addition to or alternative to elimination of therag layer. Embodiments of the disclosure can separate up to about 90% ofthe water content in the rag layer depending on operating temperature,crude type, electrostatic coalescers and demulsifier used, oralternatively up to about or greater than about 95% of the water contentin the rag layer.

The emulsion layer can consist of water, oil, and solids. Subjecting theemulsion layer to high voltage electric fields will result in waterdroplets being distorted into an elliptical shape, with positive chargesaccumulating at the end nearest the negative electrode of the externalelectric field, and negative charges at the end nearest the positiveelectrode. The drops become induced dipoles. Two adjacent droplets inthe field will have an electrical attraction for one another. Thenegative end of one droplet is nearest the positive end of theneighboring droplet, so there is an attractive force between the twothat tends to draw them together. This force is of sufficient magnitudeto rupture the interfacial film between the droplets upon collision, andallows them to coalesce into one larger droplet. The resulting largerwater droplets (globules), along with water-insoluble solids, settle tothe bottom of a vessel or pipe.

For purposes of the present disclosure, tight emulsion crude oilincludes emulsions that occur in medium to heavy crude oils withAmerican Petroleum Institute (API) numbers less than about 29. Crude oilspecific gravity, along with API numbers, can be used as a measure ofcrude oil quality. Higher API values indicate lighter oils and, thus, ahigher market value. Water cut in oil production refers to the totalvolume of water in the crude oil stream divided by the total volume ofcrude oil and water, or water cut percent=total volumetric flowrate ofwater/(volumetric flowrate of water+volumetric flowrate of crudeoil)*100. Water cut increases with oil and gas well age duringcontinuous production of oil and gas wells. Water cut at the beginningof the well life can be around zero percent and can reach close to 100%by the end of the life of the well. “Wet” crude oil normally has morethan about 0.3 volume percent of water while “dry” crude has less than0.3 volume percent water.

Insulated electrostatic electrodes can be similar to those of WartsilaCorporation of Helsinki, Finland produced under the term Vessel InternalElectrostatic Coalescers (VIEC). Another supplier of suitable electrodeswould include Cameron International Corporation (a Schlumberger Company)of Houston, Tex. Emulsion separation vessel technology described in U.S.Pat. No. 10,513,663 is suitable in certain embodiments of the presentdisclosure and is incorporated here by reference in its entirety.Fully-insulated electrostatic electrodes 128, 182 are capable ofhandling up to 100% water cut, and the electrodes can be fullydeactivated at about 100% water cut.

Initially-treated crude oil then proceeds via stream 138 to mixing valve140 to be mixed with additional recycle water from stream 142 generatedas the bottom stream from desalter 193. After mixing in mixing valve140, the mixed crude oil and recycle water proceed to a heat exchanger146 for heating via compressed high pressure gas from stream 148 andhigh pressure compressor 150. Heat exchanger 146 can include any one ofor any combination of indirect heat exchangers such as shell and tubeheat exchangers, and cooled gases proceed via stream 152 to a highpressure knockout drum 154 for separation of condensate via stream 156,to be sent for fractionation and further processing, and natural gas tobe sent further processing to sales gas via stream 158. Heatedinitially-treated crude oil mixed with recycle water proceeds via stream160 to heat exchanger 162 for further heating. Heat exchanger 162 caninclude any one of or any combination of indirect heat exchangers suchas shell and tube heat exchangers, and additional heat is provided viaheated and compressed gases in line 166 from low pressure gas compressor134. Cooled gases from heat exchanger 162 proceed to low pressureknockout drum 170 for separation of condensate via stream 172 andoff-gases via stream 174 for compression in high pressure compressor150. Knockout drums are known in the art, and help separate natural gasfrom condensates.

After 2 stages of heating in heat exchangers 146, 162 theinitially-treated crude oil mixed with recycle water from desalter 193proceeds via stream 164 to LPDT 176, which includes a stripping gasstream 178, a weir 180, fully-insulated electrostatic electrodes 182,and cyclonic separator 183. Stripping gas stream 178 can include steamin addition to or alternative to nitrogen or other stripping gases.Stripping gas streams as described herein are optional, and can beapplied as needed for removal of H₂S from sour crude oil. Off-gases fromLPDT 176 proceed via stream 184 to atmospheric gas compressor 121 forcompression and heating. Operating conditions in LPDT 176 can include atemperature in a range from about 65° F. to about 130° F. and a pressurebetween about 3 psig to about 5 psig, or vacuum can be applied at LPDT176, or the pressure can be up to about 10 psig.

LPDT-treated crude oil next proceeds via stream 185 to crude oil chargepump 186, then via stream 187 to trim heat exchanger 188 for furtherheating prior to proceeding via stream 189 to mixing valve 190 formixing with fresh wash water from stream 191. LPDT-treated crude oilmixed with fresh wash water proceeds via stream 192 to desalter 193 fordesalting of the crude oil. Typically, wash water salinity ranges fromabout 100 ppm to about 12,000 ppm salt in embodiments of the presentdisclosure, for example in wash water stream 191. Wash water will bemore effective at lower salinity. Formation water salinity inside crudeoil can reach as high as 270,000 ppm of salt content. Demulsifiers, oremulsion breakers, are chemicals used to separate emulsions (for exampleoil-in-water emulsions). Some commercially available demulsifiers arePetrolite DMO-22241 by Baker Petrolite, Emulsotron CC-8948 by ChampionTechnologies, SUGEST 9005 by German Metal Surface Treatment ChemicalCo., Clariant Phasetreat 4688 by Clariant, or any other suitabledemulsifier.

For example, a separation vessel operating pressure can be in the rangeof about 1 psig to about 10 psig, and a desalter operating pressure canbe greater than about 35 psig, depending on the vapor pressure of thefluid inside the desalter. Crude oil fed to a desalter is required to bebelow its bubble point to ensure no free vapor is liberated in theprocess. Desalters are designed to be ‘gas free,’ since the presence ofvapor in a high voltage field can cause arcing which in turn leads tomore vapor formation. Desalters can operate at about 25 psig higher thanthe fluid vapor pressure to avoid vaporization inside the desalters andpotential arcing.

Afterward, LPDT-treated, desalted crude oil proceeds via stream 194,valve 195, and stream 196 to cold stabilizer 197, which in theembodiment shown does not include reboilers. Stripping stream 198 isshown and is used as needed to remove remaining H₂S, and stream 198 caninclude steam in addition to or alternative to other stripping gasessuch as nitrogen. Heated sales-grade crude oil proceeds via stream 199and pump 127 to first heat inlet crude in heat exchanger 116 beforeproceeding to export via stream 117. Atmospheric off-gases proceed fromcold stabilizer 197 to atmospheric gas compressor 121 for compressionand heating via stream 123. Notably, the system of FIG. 1 operates inthe absence of a high pressure production trap, a separate dehydratorvessel, a second stage desalter, or stabilizer reboilers.

FIG. 2 is a schematic diagram showing an integrated GOSP of the presentdisclosure used for processing sweet or slightly sour crude oil withintegrated gas compression. Embodiments of systems and processes similarto FIG. 2 are suitable for use in situations where crude oil is sweet orcontains low levels of sulfur. The direct injection of heated highpressure gas following compression in a low pressure gas compressor intoincoming crude oil to a high pressure production trap (HPPT) willsimultaneously heat the crude and cool the gas. This heated gasfunctions, in part, as a stripping gas in the HPPT and enables meetingan H₂S crude specifications of 10 ppm without using a crude oilstabilizer, such as cold stabilizer 197 in FIG. 1. Gas from low pressureand high pressure compressors is used in low pressure and high pressuregas-crude heat exchangers to heat crude oil, recover energy, and coolthe gas. The representative embodiments of FIGS. 1 and 2 improve crudeoil yield at the expense of condensate, or in other words surprisinglyand unexpectedly produce additional high quality crude for export whilereducing the amount of lower value condensate produced.

In integrated compression GOSP system and process 200, a wet andunstabilized crude oil from oil production wells, either or both onshoreor offshore, for example at about 63° F., or between about 40° F. and80° F., enters through inlet stream 202 and is mixed with an optionaldemulsifier from demulsifier inlet stream 204 to enter inline gasseparator 206 which removes certain volatile off-gases from the crudeoil via off-gas stream 205. Off-gases in off-gas stream 205 proceed to ahigh pressure gas compressor 274 for compression and heating. Mixedcrude oil and optional demulsifier proceed to a mixing valve 210 bystream 208, and at mixing valve 210 a recycled water stream from lowpressure production trap (LPPT) 252 is mixed into the crude oil andoptional demulsifier. After mixing valve 210 the mixed stream proceedsvia stream 218 to direct gas-crude mixer 220 for heating of the crudeoil, recycle water, and optional demulsifier. Heated high pressure gasis provided via stream 219 from low pressure gas compressor 262.

The high pressure compressed and heated off-gas from stream 219 and lowpressure gas compressor 262 provides further heating to the mixed streamcomprising crude oil, recycle water, and optional demulsifier and alsoacts as a stripping gas for H₂S, if necessary. The mixed stream ofoff-gas, crude oil, recycle water, and optional demulsifier proceeds toHPPT 224, which includes a weir 226, fully-insulated electrostaticelectrodes 228, and cyclonic separator 230. HPPT 224 is a horizontalthree-phase separation vessel, which separates certain off-gases fromthe wet crude oil. Outlets from HPPT 224 include HPPT high pressureoff-gas stream 232, which proceeds to high pressure gas compressor 274for compression and heating, oily-water outlet stream 236 which proceedsvia stream 236 for water treatment in oily-water treatment unit 324, andHPPT wet crude oil outlet stream 238, which proceeds to downstreamprocessing. Operating conditions in the HPPT include temperature in arange from about 65° F. to about 130° F., and pressure at about 150pounds per square inch gauge (psig), or between about 100 psig and about450 psig. After treatment, any remaining oily-water waste can proceed towaste disposal wells via stream 326.

Initially-treated crude oil then proceeds via stream 238 to mixing valve240 to be mixed with additional recycle water from stream 242 generatedas the bottom stream from LPDT 300. After mixing in mixing valve 240,the mixed crude oil and recycle water proceed to a direct gas-crudemixer 246 for heating via compressed high pressure gas from stream 248and atmospheric pressure gas compressor 292. LPPT 252 includes acyclonic separator 254, a weir 256, and fully-insulated electrostaticelectrodes 258. In the embodiment shown, the inlet temperature of themixed stream to LPPT 252 can be about 140° F., or between about 100° F.and 150° F. In LPPT 252 off-gas is separated via stream 260 and proceedsto low pressure gas compressor 262, recycle water is separated viastream 212, and LPPT-treated crude oil proceeds via stream 264 to mixingvalve 268 for mixing with wash water from stream 266. Operatingconditions in LPPT 252 include temperature in a range from about 65° F.to about 130° F. and a pressure at about 50 psig, or between about 20psig and 60 psig.

Mixed wash water and crude oil proceed from mixing valve 268 via stream270 to heat exchanger 278 for heating by hot high pressure compressedgas from stream 276 and high pressure gas compressor 274. Heat exchanger278 can include any one of or any combination of indirect heatexchangers such as shell and tube heat exchangers, and cooled gasesproceed via line 282 to a high pressure knockout drum 312 for separationof condensate via line 314, to be sent for further processing andfractionation, and natural gas to be sent for further processing tosales gas via line 316. Heated LPPT-treated crude oil mixed with washwater proceeds via stream 280 to trim heat exchanger 284 for furtherheating. Trim heat exchanger 284 can include any one of or anycombination of indirect heat exchangers such as shell and tube heatexchangers or an electric heater. LPPT-treated crude oil mixed with washwater, in some embodiments heated to about 180° F., or between about150° F. and 200° F., proceeds via stream 286 to inline gas separator 288for separation of off-gases at about atmospheric pressure via stream 290to atmospheric pressure gas compressor 292.

Partially de-gassed crude oil mixed with wash water proceeds via stream294, and optional stripping gas in addition to or alternative to steamcan be provided at stream 296 before LPDT 300. LPDT 300 includescyclonic separator 302, weir 304, and fully-insulated electrostaticelectrodes 306. Optional stripping gas in addition to or alternative tosteam can be applied to LPDT 300 via stream 308. Operating conditions inLPDT 300 can include a temperature in a range from about 65° F. to about130° F. and a pressure between about 3 psig to about 5 psig, or vacuumcan be applied at LPDT 300, or the pressure can be up to about 10 psig.Dry, stabilized crude for export, and any remaining natural gas forfurther processing, proceed via stream 318 to crude oil pump 320 andstream 322. Notably, the system of FIG. 2 does not include separatedesalting units, separate dehydrating units, a stabilizer, or reboilers.

Typically, wash water salinity ranges from about 100 ppm to about 12,000ppm salt in embodiments of the present disclosure, for example in washwater stream 266. Wash water will be more effective at lower salinity.Formation water salinity inside crude oil can reach as high as 270,000ppm of salt content. Demulsifiers, or emulsion breakers, are chemicalsused to separate emulsions (for example oil-in-water emulsions). Somecommercially available demulsifiers are Petrolite DMO-22241 by BakerPetrolite, Emulsotron CC-8948 by Champion Technologies, SUGEST 9005 byGerman Metal Surface Treatment Chemical Co., Clariant Phasetreat 4688 byClariant, or any other suitable demulsifier.

In some embodiments of FIG. 2, a pressure drop in HPPT 224 causeslighter hydrocarbon gases in the crude oil to separate from the heavierliquid hydrocarbons. The plurality of fully-insulated electrostaticelectrodes 228 simultaneously dehydrates crude oil and removesemulsified water, for example up to 98% of emulsified water. Theoperating pressure of LPPT 252 is less than HPPT 224, and LPPT 252removes any remaining off-gas and emulsified water. LPPT 252 is ahorizontal three-phase separation vessel. Operating pressure of LPPT 252in some embodiments is about ⅓ of HPPT 224 operating pressure in orderto maximize separated liquid recovery.

Partially dry crude oil in stream 264 following LPPT 252 still containslight components or impurities that need to be further reduced. Theseimpurities can include H₂S, N₂, CO₂, CH₄, C₂H₄, C₃H₆, water, or anyother suspended solids or light gases. Stream 264 is mixed with washwater from stream 266 in mixing valve 268, or any other suitable mixers,to disperse the water into small fine droplets to reduce the saltcontent or any other impurities in the crude oil. Low salinity washwater rinses the remaining salt from the crude oil. Fresh wash water canbe used in the desalting processes to ensure that the maximum amount ofsalt is rinsed from the crude oil. Injecting low salinity water beforeheat exchangers aids in minimizing fouling.

Heating crude makes it easier to separate out gas and enhance thedesalting efficiency in LPDT 300. Electrostatic coalescence removes theremaining water emulsion from the crude oil eliminating the need for 2ndstage desalters in certain prior art systems and processes. Heated crudeoil enters LPDT 300, which operates at a lower pressure than LPPT 252,and LPDT 300 finally removes remaining gas impurities from the crude oilto meet the RVP/H₂S content specifications. Dry crude oil for shipmentin stream 322 in some embodiments meets specifications including thefollowing: (1) a salt concentration of not more than about 10 PTB; (2)BSW of not more than about 0.3 V %; (3) H₂S content of less than about60 ppm in the crude stabilization tower (or degassing vessels in thecase of sweet crude); and (4) a maximum RVP of about 7 psia and amaximum TVP of about 13.5 psia at 130° F.

Wet crude oil generally contains some free salty water, and salty waterin the form of an emulsion. The emulsion is separated into layers of oiland water by electrostatic coalescence. Electrostatic coalescenceapplies an electric current, causing water droplets in an emulsion tocollide, coalesce into larger (heavier) drops, and settle out of thecrude oil as separate liquid water. This process partially dries wetcrude oil.

Stabilization is a process carried out using heating to remove anyremaining dissolved gases, light, volatile hydrocarbons, and H₂S. Crudeoil is hence split into two components: atmospheric gas from theoverhead, for example at stream 123, and stabilized, sweetened crude oilfrom the bottoms, for example at cold stabilizer product bottom stream199. Stabilizing crude oil is achieved when crude oil is heated in amultiple stages of separation drums working at increasing temperaturesand reduced pressure.

Cold stabilizer 197 performs two functions simultaneously by sweeteningsour crude oil by removing the hydrogen sulfide, and reducing the vaporpressure through removal of light, volatile hydrocarbons, thereby makingthe crude oil safe for shipment in pipelines. Stabilization involves theremoval of light ends from crude oil, mainly C₁-C₄ hydrocarbons, toreduce the vapor pressure to produce dead or stable product that can bestored in an atmospheric tank. Stabilization aims to lower vaporpressure of crude oil to a maximum RVP of about 7 psia and a maximum TVPof about 13.5 psia at 130° F., or in other words low enough so no vaporwill flash under atmospheric conditions, making it safe fortransportation and shipment. Operating conditions of a stabilizer, suchas for example cold stabilizer 197, include temperature in a range fromabout 160° F. to about 200° F. and pressure from about 3 psig to about 5psig.

Higher LPPT and HPPT operating temperatures also aid in crude sweeteningand stabilization, for example in cold stabilizer 197. In someembodiments, integrated compression GOSP systems and processes 100 and200 can be used to process light crude or extra light crude grades. Forexample, in some applications in Saudi Arabia, crude oil grade ismeasured by the American Petroleum Institute (API) range as follows:Arabian Super Light (49-52 API); Arabian Extra Light (37-41 API); andArabian Light (32-36 API). API=141.5/(crude oil specific gravity)-131.5.

For the systems of FIGS. 1 and 2, flow loop tests were performed toverify the applicability of the internal electrostatic electrodes andeffectiveness inside the three-phase separators, such as HPPT's, LPPT's,and LPDT's.

Wet crude oil as used in the specification generally refers to crude oilhaving more than about 0.3 volume percent of water, while dry crude oilhas less than about 0.3 volume percent of water. The phrase lighterhydrocarbons as used throughout the specification refers generally toC₁₋₄ components such as, for example, methane, ethane, propane, butane,iso-butane, and trace amounts of C₅₊ compounds. The phrase heavierhydrocarbons as used in the specification refers generally to C₅₊ orfive-carbon and greater hydrocarbons such as, for example, pentane,is-pentane, hexane, and heptane. Heavier hydrocarbons can have traceamounts of lighter hydrocarbons.

HPPT high pressure off-gas stream 232, in some embodiments, ranges frombetween about 150 psig to about 450 psig, depending on the crude oilsupply pressure. HPPT high pressure off-gas stream 232 can includelighter hydrocarbons, traces of C₅₊ hydrocarbons, H₂S, CO₂, N₂, andwater vapor; however, the relative amounts and types of compounds willdepend on the crude oil inlet feed stream.

LPPT low pressure off-gas stream 260 ranges from between about 50 psigto about 90 psig. LPPT low pressure off-gas stream 260 can includelighter hydrocarbons, traces of C₅₊ hydrocarbons, H₂S, CO₂, N₂, andwater vapor; however, the relative amounts and types of compounds willdepend on the crude oil inlet feed stream.

In some embodiments of LPDT 300, pressure is reduced to about 3 psig, sothat any remaining heavy gas components can boil off. Heavy gascomponents in the case of LPDT 300 can include propane, butane,iso-butane, H₂S, CO₂, and C₅₊ hydrocarbons; however, the relativeamounts and types of compounds will depend on the crude oil inlet feedstream.

Operating conditions of a desalter such as desalter 193 can include atemperature range from about 130° F. to about 160° F. and a pressure atabout 25 psig above the crude vapor pressure.

Second stage desalters are not required in embodiments of the presentdisclosure. Sweetening involves the removal of dissolved H₂S gas fromcrude oil to meet specifications in a range of about 10-60 ppm H₂S.Sweetening is performed to reduce corrosion to pipelines and eliminatehealth and safety hazards associated with H₂S. Steam can be used tostrip H₂S gas from crude oil in addition to or alternative to any othersuitable stripping gas that is low in H₂₅ concentration relative to thecrude oil. Suitable stripping gas streams include natural gas low in H₂Sconcentration (such as methane and ethane), steam, and nitrogen (N₂).

Stabilization operates by heating unstabilized crude oil containingdissolved gases and H₂S, and splitting it into two components: gas froman overhead stream and crude oil from a bottoms stream. Stabilizingcrude oil can be achieved if crude oil is heated in multiple stages ofseparation drums working at increasing temperatures and reducedpressure, such as for example in cold stabilizer 197. Oil stabilizationunits perform two functions at the same time, which include sweeteningsour crude oil by removing hydrogen sulfide and reducing vapor pressure,thereby making the crude safe for shipment in pipelines.

Stabilization involves the removal of light ends, mainly C₁-C₄hydrocarbons, from crude oil, to reduce the vapor pressure to produce aless volatile and stable product that can be stored in an atmospherictank. Stabilization also aims to lower vapor pressure of crude oil to atleast about 13 psia below atmospheric pressure, so no vapor will flashunder atmospheric conditions, making it safe for transportation andshipment. The operating temperature of the cold stabilizer 197 rangesfrom about 160° F. to about 200° F., and the pressure ranges from about3 to about 5 psig.

Cold stabilizer 197 has a number of trays (for example, up to aboutsixteen), whereby crude oil flows down over each tray until it reaches adraw-off tray.

The systems and processes represented by FIG. 2 advantageously allow foreliminating a crude oil stabilizer, such as for example cold stabilizer197, eliminating crude stabilizer reboilers, such as for examplethermosiphon reboilers, eliminating certain crude charge pumps, such asfor example crude oil charge pump 186, and eliminating a first stagedesalter, such as for example desalter 193. Further benefits includeintegrated GOSP systems and methods being compact, efficient, and easilymobilized, transportable, and deployable in small-scale and offshoreapplications. Embodiments of the present disclosure reduce the need forunits in land-based onshore applications, while also reducing costs ofoperation.

For certain embodiments of disclosed systems and methods, for examplethose of FIGS. 1 and 2, suitable approximate operating temperature andpressure ranges for units, inlets, and outlets are shown in Tables 1, 2,and 3 below.

TABLE 1 Suitable temperature and pressure ranges for certain unitsdescribed. Vessel Temperature, ° F. Pressure, psig Inline Cyclonic 50-60 145-200 Separator HPPT  80-100 135-165 LPPT 100-140  35-60 LPDT100-150   3-15 Dehydrator 120-180  90-200 Desalter 120-180  90-200Stabilizer 120-220  3-15 Atm Comp 100-150  3-15 Suction KOD Atm Comp210-290  45-80 Discharge KOD LP Comp 100-150  35-70 Suction KOD LP Comp210-290 145-180 Discharge KOD HP Comp 100-150 135-170 Suction KOD HPComp 210-290 420-500 Discharge KOD

TABLE 2 Suitable temperature and pressure ranges for certain unitsdescribed. Inlet Outlet Unit Temp, ° F. Press, psig Temp, ° F. Press,psig Atm 100-150   3-15 210-290  45-80 Compressor LP 100-150  35-70210-290 145-180 Compressor HP 100-150 135-170 210-290 420-500 Compressor

TABLE 3 Suitable temperature and pressure ranges for certain unitsdescribed. Wet Crude Temperature, ° F. Unit Inlet Outlet 1st Heat  50-90 60-110 Exchanger 2nd Heat  60-110 120-130 Exchanger Trim Heater 120-130150-180

Demulsifiers enhance desalting processes and allow treatment of “tight”emulsions. Also referred to as emulsion breakers, demulsifiers arechemicals used to separate emulsions such as, for example, water in oil.For example, one such demulsifier is PHASETREAT® by Clariant of Muttenz,Switzerland.

The composition of high pressure off-gases, low pressure off-gases, andatmospheric pressure off-gases will vary depending on the temperatureand pressure of an HPPT, LPPT, and LPDT. Moreover, the composition ofhigh pressure off-gases, low pressure off-gases, and atmosphericpressure off-gases will depend on the inlet temperature, pressure, andcomposition of crude oil. A low pressure off-gas will have highermolecular weight compounds than a high pressure off-gas, and anatmospheric pressure off-gas will have higher molecular weight compoundsthan a low pressure off-gas. In some embodiments, a high pressurecompressor accepts high pressure off-gas at about 150 psig andcompresses the high pressure off-gas to about 450 psig; a low pressurecompressor accepts low pressure off-gas at about 50 psig and compressesthe low pressure off-gas to about 160 psig; and an atmospheric pressurecompressor accepts atmospheric pressure off-gas at about 0.7 psig andcompresses the atmospheric pressure off-gas to about 60 psig.

Efficient inlet mixing devices and cyclonic separators improve theseparation of gas and liquid in vessels such as an HPPT, LPPT, and LPDT,and thus the size of vessels including HPPT's, LPPT's, and LPDT's can bereduced in embodiments of the present invention.

Inline gas separators include compact gas/liquid separators that applycyclonic separation techniques to generate high gravitational forces(“G-Forces”) with a low pressure drop to achieve high separationperformance of gas from liquid in a pipe spool. Inline separators can beconsidered as one equilibrium separation stage, and produce very highquality separate gas and liquid streams.

Additional benefits of the systems and processes described here includeeliminating crude stabilizer columns and reboilers, eliminating crudecharge pumps, eliminating 1^(st) and/or 2^(nd) stage desalters,eliminating crude dehydrator units, and compacting multiple stage GOSP'sinto a single, mobile GOSP unit.

Although the disclosure has been described with respect to certainfeatures, it should be understood that the features and embodiments ofthe features can be combined with other features and embodiments ofthose features.

Although the disclosure has been described in detail, it should beunderstood that various changes, substitutions, and alterations can bemade hereupon without departing from the principle and scope of thedisclosure. Accordingly, the scope of the present disclosure should bedetermined by the following claims and their appropriate legalequivalents.

The singular forms “a,” “an,” and “the” include plural referents, unlessthe context clearly dictates otherwise. The term “about” in someembodiments includes values 5% above or below the value or range ofvalues provided.

As used throughout the disclosure and in the appended claims, the words“comprise,” “has,” and “include” and all grammatical variations thereofare each intended to have an open, non-limiting meaning that does notexclude additional elements or steps.

As used throughout the disclosure, terms such as “first” and “second”are arbitrarily assigned and are merely intended to differentiatebetween two or more components of an apparatus. It is to be understoodthat the words “first” and “second” serve no other purpose and are notpart of the name or description of the component, nor do theynecessarily define a relative location or position of the component.Furthermore, it is to be understood that that the mere use of the term“first” and “second” does not require that there be any “third”component, although that possibility is contemplated under the scope ofthe present disclosure.

While the disclosure has been described in conjunction with specificembodiments thereof, it is evident that many alternatives,modifications, and variations will be apparent to those skilled in theart in light of the foregoing description. Accordingly, it is intendedto embrace all such alternatives, modifications, and variations as fallwithin the spirit and broad scope of the appended claims. The presentdisclosure may suitably comprise, consist or consist essentially of theelements disclosed and may be practiced in the absence of an element notdisclosed.

What is claimed is:
 1. An integrated gas oil separation plant system,the system comprising: a crude oil inlet feed stream; a low pressureproduction trap (LPPT), where the LPPT is fluidly coupled to the crudeoil inlet feed stream, and where the LPPT comprises an inlet mixingdevice operable to thoroughly mix an LPPT inlet feed stream, a pluralityof insulated electrostatic electrodes, and a weir; a low pressuredegassing tank (LPDT), where the LPDT is fluidly coupled to the LPPT,and where the LPDT comprises an inlet mixing device operable tothoroughly mix an LPDT inlet feed stream, a plurality of insulatedelectrostatic electrodes, and a weir; a first heat exchanger, where thefirst heat exchanger is fluidly disposed between the LPPT and LPDT, andis fluidly coupled to both the LPPT and LPDT, and where the first heatexchanger is operable to heat the LPDT inlet feed stream with compressedgas, the gas removed from the crude oil inlet feed stream; a firstinline gas mixer preceding the LPPT to directly mix compressed gasremoved from the LPDT into the LPPT inlet feed stream; and a LPDTrecycle water stream, where the LPDT recycle water stream is operable tosupply recycle water from the LPDT to the LPPT inlet feed stream.
 2. Thesystem according to claim 1, further comprising an inline gas separatorpreceding the LPPT to separate gas from the crude oil inlet feed streamfor compression, and wherein compressed gas from the inline gasseparator and compressed off-gas from the LPPT is used to provide heatin the first heat exchanger.
 3. The system according to claim 1, furthercomprising a second heat exchanger, where the second heat exchanger isfluidly disposed between the LPPT and LPDT, and is fluidly coupled toboth the LPPT and LPDT, and where the second heat exchanger is operableto heat the LPDT inlet feed stream with compressed gas, the gas removedfrom the crude oil inlet feed stream.
 4. The system according to claim3, further comprising a first knock out drum in fluid communication withthe first heat exchanger and a second knockout drum in fluidcommunication with the second heat exchanger, wherein after compressedgas passes through the second knockout drum the compressed gas comprisesnatural gas for further processing to a sales gas.
 5. The systemaccording to claim 4, further comprising a desalter and a coldstabilizer, wherein atmospheric off-gas from the cold stabilizer iscompressed and sent to the first inline gas mixer preceding the LPPT andwherein dry crude oil from the cold stabilizer is used to heat the crudeoil inlet feed stream.
 6. The system according to claim 5, wherein thecold stabilizer has about 16 actual stages.
 7. The system according toclaim 1, wherein the system comprises an atmospheric pressure gascompressor and a low pressure gas compressor.
 8. The system according toclaim 4, wherein the system comprises an atmospheric pressure gascompressor, a low pressure gas compressor, and a high pressure gascompressor, and wherein the atmospheric pressure gas compressorcompresses atmospheric off-gases from the LPDT and the cold stabilizerfor supply to the first inline gas mixer, the low pressure gascompressor compresses low pressure off-gases from an inline gasseparator and the LPPT for supply to the first heat exchanger, and thehigh pressure gas compressor compresses high pressure off-gases from thefirst heat exchanger for supplying heat to the second heat exchanger. 9.The system according to claim 1, further comprising a fresh wash watersupply stream, where the fresh wash water supply stream is operable tosupply fresh water to an output stream of the LPDT.
 10. The systemaccording to claim 1, further comprising a stripping gas stream inletfluidly coupled with the LPDT, the stripping gas stream inlet operableto supply steam, in addition to or alternative to a low concentrationH₂S stripping gas, to the LPDT.
 11. The system according to claim 1,further comprising an oil/water separator device operable to accept anoily water output stream from the LPPT, and operable to separate oilfrom water.
 12. The system according to claim 1, where the system isoperable to refine crude oil in the crude oil inlet feed stream toproduce a refined crude oil product safe for storage and shipmentmeeting the following specifications: (1) a salt concentration of notmore than about 10 pound (lbs.) of salt/1000 barrels (PTB); (2) basicsediment and water (BSW) of not more than about 0.3 volume percent (V%); (3) H₂S concentration of less than about 60 ppm; and (4) a maximumRVP of about 7 pounds per square inch absolute (psia) and a maximum truevapor pressure (TVP) of about 13.5 psia at 130 degrees Fahrenheit (°F.).
 13. The system according to claim 1, further comprising a highpressure production trap (HPPT), where the HPPT is fluidly coupled tothe crude oil inlet feed stream and precedes the LPPT, and where theHPPT comprises an inlet mixing device operable to thoroughly mix thecrude oil inlet feed stream with an additional fluid, a plurality ofinsulated electrostatic electrodes, and a weir.
 14. The system accordingto claim 13, further comprising a high pressure inline gas separatorpreceding the HPPT to separate gas from the crude oil inlet feed streamfor compression and a second inline gas mixer preceding the HPPT todirectly mix compressed off-gas from the LPPT into an HPPT inlet feedstream.
 15. The system according to claim 14, further comprising a LPPTrecycle water stream, where the LPPT recycle water stream is operable tosupply recycle water from the LPPT to be mixed with the HPPT inlet feedstream.
 16. The system according to claim 13, wherein the systemcomprises an atmospheric pressure gas compressor, a low pressure gascompressor, and a high pressure gas compressor, and wherein theatmospheric pressure gas compressor compresses atmospheric off-gasesfrom the LPDT and from an atmospheric pressure inline gas separatorpreceding the LPDT to be sent to the first inline gas mixer, the lowpressure gas compressor compresses low pressure off-gases from the LPPTto be sent to the second inline gas mixer, and the high pressure gascompressor compresses high pressure off-gases from the crude oil inletfeed stream and the HPPT to be sent to the first heat exchanger.
 17. Thesystem according to claim 13, further comprising a fresh wash watersupply stream, where the fresh wash water supply stream is operable tosupply fresh water to an output stream of the LPPT.
 18. The systemaccording to claim 13, further comprising a stripping gas stream inletfluidly coupled with the LPDT, the stripping gas stream inlet operableto supply steam, in addition to or alternative to a low concentrationH₂S stripping gas, to the LPDT.
 19. The system according to claim 13,further comprising an oil/water separator device operable to accept anoily water output stream from the HPPT, and operable to separate oilfrom water.
 20. The system according to claim 13, where the system isoperable to refine crude oil in the crude oil inlet feed stream toproduce a refined crude oil product safe for storage and shipmentmeeting the following specifications: (1) a salt concentration of notmore than about 10 pound (lbs.) of salt/1000 barrels (PTB); (2) basicsediment and water (BSW) of not more than about 0.3 volume percent (V%); (3) H₂S concentration of less than about 60 ppm; and (4) a maximumRVP of about 7 pounds per square inch absolute (psia) and a maximum truevapor pressure (TVP) of about 13.5 psia at 130 degrees Fahrenheit (°F.).
 21. The system according to claim 16, further comprising a highpressure knockout drum to accept high pressure gas from the first heatexchanger and operable to produce a suitable natural gas for furtherprocessing to a sales gas.
 22. The system according to claim 13, furthercomprising at least one mixing valve preceding the HPPT, at least onemixing valve preceding the LPPT, and at least one mixing valve precedingthe first heat exchanger, where the mixing valves are operable to mixcrude oil and water.
 23. The system according to claim 13, wherein theHPPT is operable to remove about 98% of emulsified water present incrude oil from the crude oil inlet feed stream.
 24. The system accordingto claim 13, wherein operating pressure within the HPPT is greater thanthe operating pressure within the LPPT, and where the operating pressurewithin the LPPT is greater than the operating pressure in the LPDT. 25.The system according to claim 13, wherein the system is operable todehydrate, desalt, sweeten, and stabilize crude oil to produce crude oilsafe for storage and shipment without any dehydrating or desalting unitsother than the HPPT, LPPT, and LPDT.
 26. The system according to claim1, wherein at least one inlet mixing device comprises a cyclonicseparator.
 27. A method for integrated gas oil separation, the methodcomprising the steps of: supplying a crude oil inlet feed stream;removing from the crude oil inlet feed stream a low pressure crude oiloff-gas stream for compression; heating the crude oil inlet feed streamwith heat provided by processed dry crude oil; mixing the crude oilinlet feed stream with compressed low pressure gas from a low pressuredegassing tank (LPDT) and a cold stabilizer; initially separating thecrude oil inlet feed stream in a low pressure production trap (LPPT)into a LPPT off-gas stream, the LPPT off-gas stream to be compressedwith the low pressure crude oil off-gas stream, a partially-dried crudeoil stream, and an oily-water stream for treatment; heating thepartially-dried crude oil stream with compressed gas from the lowpressure crude oil off-gas stream and the LPPT off-gas stream; furtherseparating the partially-dried crude oil stream in the LPDT to produce aLPDT off-gas stream, a dried crude oil stream, and a recycle waterstream for recycle to the crude oil inlet feed stream; desalting thedried crude oil stream to produce a dried, desalted crude oil stream anda recycle water stream for recycle to the LPDT; stabilizing the dried,desalted crude oil stream to produce a crude oil export stream, thecrude oil export stream used to heat the crude oil inlet feed stream,and an atmospheric off-gas stream; and compressing the LPDT off-gasstream and the atmospheric off-gas stream for the step of mixing thecrude oil inlet feed stream with compressed low pressure gas from thelow pressure degassing tank (LPDT) and the cold stabilizer.
 28. Themethod according to claim 27, wherein the LPPT comprises an inlet mixingdevice operable to thoroughly mix an LPPT inlet feed stream, a pluralityof insulated electrostatic electrodes, and a weir; and wherein the LPDTcomprises an inlet mixing device operable to thoroughly mix an LPDTinlet feed stream, a plurality of insulated electrostatic electrodes,and a weir.
 29. The method according to claim 27, wherein the step ofremoving from the crude oil inlet feed stream a low pressure crude oiloff-gas stream for compression includes the use of an inline gasseparator preceding the LPPT.
 30. The method according to claim 27,further comprising the step of removing condensate from compressedoff-gas using at least one knock-out drum.
 31. The method according toclaim 27, further comprising the step of supplying a fresh water washstream to aid in the step of desalting.
 32. The method according toclaim 27, further comprising the step of supplying a stripping gasstream, the stripping gas stream to supply steam, in addition to oralternative to a low concentration H₂S stripping gas.
 33. The methodaccording to claim 27, where the method is operable to refine crude oilin the crude oil inlet feed stream to produce a refined crude oilproduct safe for storage and shipment meeting the followingspecifications: (1) a salt concentration of not more than about 10 pound(lbs.) of salt/1000 barrels (PTB); (2) basic sediment and water (BSW) ofnot more than about 0.3 volume percent (V %); (3) H₂S concentration ofless than about 60 ppm; and (4) a maximum RVP of about 7 pounds persquare inch absolute (psia) and a maximum true vapor pressure (TVP) ofabout 13.5 psia at 130 degrees Fahrenheit (° F.).
 34. A method forintegrated gas oil separation, the method comprising the steps of:supplying a crude oil inlet feed stream; removing from the crude oilinlet feed stream a high pressure crude oil off-gas stream forcompression; mixing the crude oil inlet feed stream with recycle waterfrom a low pressure production trap (LPPT); mixing the crude oil inletfeed stream with compressed high pressure gas from the LPPT; initiallyseparating the crude oil inlet feed stream in a high pressure productiontrap (HPPT) into a HPPT off-gas stream, the HPPT off-gas stream to becompressed with the high pressure crude oil off-gas stream, a HPPTpartially-dried crude oil stream, and an oily-water stream fortreatment; mixing the HPPT partially-dried crude oil stream with recyclewater from a low pressure production trap (LPDT) and with compressedatmospheric gas from the LPDT; separating the HPPT partially-dried crudeoil stream in the LPPT into a LPPT off-gas stream, the LPPT off-gasstream to be compressed for mixing with the crude oil inlet feed stream,an LPPT partially-dried crude oil stream, and an oily-water recyclestream; heating the LPPT partially-dried crude oil stream withcompressed gas from the high pressure crude oil off-gas stream and theHPPT off-gas stream; removing from the LPPT partially-dried crude oilstream an atmospheric pressure off-gas stream; and further separatingthe LPPT partially-dried crude oil stream in the LPDT to produce a LPDToff-gas stream, the LPDT off-gas stream to be compressed with theatmospheric pressure off-gas stream, a dried crude oil stream, and arecycle water stream for recycle to the LPPT.
 35. The method accordingto claim 34, wherein the HPPT comprises an inlet mixing device operableto thoroughly mix an HPPT inlet feed stream, a plurality of insulatedelectrostatic electrodes, and a weir; wherein the LPPT comprises aninlet mixing device operable to thoroughly mix an LPPT inlet feedstream, a plurality of insulated electrostatic electrodes, and a weir;and wherein the LPDT comprises an inlet mixing device operable tothoroughly mix an LPDT inlet feed stream, a plurality of insulatedelectrostatic electrodes, and a weir.
 36. The method according to claim34, wherein the step of removing from the crude oil inlet feed stream ahigh pressure crude oil off-gas stream for compression includes the useof an inline gas separator preceding the HPPT.
 37. The method accordingto claim 34, further comprising the step of removing condensate fromcompressed off-gas using at least one knock-out drum.
 38. The methodaccording to claim 34, further comprising the step of supplying a freshwater wash stream to aid in desalting of crude oil.
 39. The methodaccording to claim 34, further comprising the step of supplying astripping gas stream, the stripping gas stream to supply steam, inaddition to or alternative to a low concentration H₂S stripping gas. 40.The method according to claim 34, where the method is operable to refinecrude oil in the crude oil inlet feed stream to produce a refined crudeoil product safe for storage and shipment meeting the followingspecifications: (1) a salt concentration of not more than about 10 pound(lbs.) of salt/1000 barrels (PTB); (2) basic sediment and water (BSW) ofnot more than about 0.3 volume percent (V %); (3) H₂S concentration ofless than about 60 ppm; and (4) a maximum RVP of about 7 pounds persquare inch absolute (psia) and a maximum true vapor pressure (TVP) ofabout 13.5 psia at 130 degrees Fahrenheit (° F.).